Raising recovery rate is industry imperative

Critical D&C issues with Vik Rao, Halliburton

Vik Rao is senior vice president of technology for Halliburton.

DC: What do you see as the most critical issue facing the drilling and completion industry today?

Rao: I would say the biggest issue is simply meeting demand. Inability to meet demand is why prices are so high right now. Yes, there are other contributing factors from the downstream side, from speculation, from geopolitical instability, etc. But even accounting for those factors, the price is still high.

For the first time in my 30-odd years in the industry, we are seriously talking about plateauing production, which was introduced by TOTAL CEO Christophe De Margerie. He basically said world production would plateau at 100 million bbl/day. For perspective, the world currently consumes about 86 million bbls/day. This doesn’t seem to be a big factor for the immediate few years. But it is a factor because considerations that cause people to believe there may be a plateauing in production are in play now.

With all that said, what is imperative? It is to increase net recoveries from existing fields and future prospects. That is operators’ singular most important objective today. Typically, current net recovery is in the low 30 percentile. In other words, we’re leaving two-thirds of the oil and gas behind. There is a belief in the industry, which I share, that if the net recovery rate were increased by 10 percentage points, that would add a trillion bbls to reserves.

Interestingly, increasing net recoveries is an objective shared by both IOCs and NOCs. For NOCs, that’s almost their singular objective. For IOCs, however, their access to conventional hydrocarbons has decreased, so they’ve been pushed in the direction of unconventionals. So the two critical imperatives driving the operators  right now are increased focus on unconventional hydrocarbons primarily by IOCs and increased focus on increasing net recoveries by everybody.

DC: What are the expectations that the industry can go from, say a 30% to a 40% recovery rate?

Rao: With significant research, I believe that 10 percentage points is possible. If certain breakthroughs are not made, the high single digits are possible.

DC: What are some areas of downhole breakthroughs that the industry, including Halliburton, is working towards making in the next 1-2 years?

Rao: One is lower-cost completions, especially in deepwater. That’s imperative because by 2010 — and 2010 is only two years away — 50% of all production will be sand-prone. The way the industry has dealt with the problem in the past has been gravel-packing and increasingly complex screens to prevent sand from coming in. Eventually, that may prove prohibitive. Halliburton is taking a game-changing approach to that, and we should have something to reveal in 2008. It will be very significant in terms of effectively controlling sand at a lower cost.

Another area we’re working on will address unconventional hydrocarbons — basically, tight gas. Unconventional gas comprise 39% of all US production. By 2010, that’s going to be 42% to 43%. Tight gas is an important reserve for the US and other parts of the world where conventional gas is harder to come by or is far from where it needs to be used. There is LNG or GTL, but they both include an extra layer of cost.

Tight gas presents some unique challenges, one of which is predictability of production rates. It’s awful. If you draw a diagram of predicted production rates from a tight gas well versus actual, it’s a scattered graph. Sometimes you get a lot more, sometimes a lot less, and once in a while you get what you predicted. The industry and Halliburton are addressing that.

I don’t believe we treat tight gas reservoirs with respect. We evaluate them the way we do other wells, and we drill and fracture them like the others. The work that Halliburton and others are doing now will make that much more effective.

The third breakthrough we’re working on is what we call the “drilling to the earth model.” This is where drilling and completion functions get integrated with seismic functions. Right now, prospects are drilled based on an earth model — essentially a 3D picture of the earth. Drillers are told to get to a point in 3D space. In the future, it’s not a point in 3D space. It’s somewhere out there, and as you get closer, we provide a better image using LWD and other data to improve the quality of the original image. That will get you to the sweetest spot more effectively because you will be drilling more intelligently. The key will be the integration of two disciplines: seismic interpretation and drilling.

DC: Is this “drilling to the earth model” already available?

Rao: It is, but not to the level of sophistication needed to achieve the biggest gains. The issues include people’s workflows, it’s not just technology at this point.

Halliburton is uniquely positioned because we have the leading seismic interpretation company, Landmark, in our portfolio. This gives us the high-end interpretation capability we need to marry it with the drilling capability. Full integration between seismic interpretation and reservoir description with drilling ability will be necessary.

In the future, you will see the industry as a whole moving towards a more integrated approach between disciplines. It will be particularly true for unconventional hydrocarbons. Discipline demarcation between upstream and downstream will blur for heavy oil. It will almost disappear for shale oil and will be nonexistent for biofuel.

DC: Why? And in what kind of time frame will this happen?

Rao: Ten years. Take extra-heavy oil, for example. We know how to get it out of the ground, but once it’s out, moving it from point A to point B is very difficult. This oil can have the viscosity of greater than 105 centipoise. To move in a pipeline, it must be no more than 200 centipoise. So getting it from the wellhead to the refinery is a huge problem in heavy oil.

I believe that certain operations — quasi-refinery operations — will have to move to the field. What we do now with diluting the oil, taking it to the refinery, then taking the dilutant out again, is very expensive. Field upgrading will become critical so certain relatively straightforward operations to render the fluid capable of movement can be done in the field. At that point, where is upstream? There’s a downstream function on the wellhead. That’s what I mean by disciplines blurring.

DC: What is your interpretation of a smart well? What are the bottlenecks facing the industry before we can achieve a truly smart well?

Rao: A smart well is a well that yields desired reservoir fluids when it’s wanted and optimizes the recovery of the reservoir ultimately. The purpose is to optimize recovery, which as I said earlier is one of the industry’s critical imperatives today. This is done by having valving functions at various junctures in the well and in multilateral wells.

Wells of the future, at least the high-end ones, will be horizontal and multilateral with smart well technology. Sections of wells, or sections of legs of wells, will be able to be shut off or partially shut off so you can manage the reservoir. It will be important to have proper reservoir description and proper reservoir simulation so you can modify the simulation on the fly based on what the smart well is telling you, and then manage your reservoir accordingly.

DC: So what’s slowing the smart well down?

Rao: That has been bugging me for 10 years. First, it is antipathy to spending more today for gratification tomorrow. That is why multilaterals took so long to take off. It is a higher cost today for a lower production cost tomorrow, and that’s a hard pill to swallow for certain asset decision makers, especially if they’re judged in the short term. However, I think that’s turning around because the imperative on increasing net recovery is so huge. In particular, Saudi Aramco has been the industry’s most aggressive in using smart wells. That’s being driven directly by that imperative of increasing net recoveries. It also helps that industry is now offering a broader spectrum of fit-for-purpose smart wells. We realize now that sometimes you need sophistication and sometimes you need simplicity.

DC: Is the reliability of rotary steerables increasing?

Rao: The reliability of rotary steerables is increasing significantly for the major players who have been using it for a while. However, there are a lot of new entrants who are have teething problems. If you look at the industry average, I’m not sure you’d see an improvement. With the principal players like Halliburton and Baker Hughes, it’s increasing significantly.

DC: What are some improvements the industry can expect to see with rotary steerables in the coming 1-2 years?

Rao: First is rotary seals. Second is improved modeling. For us, that means if we do get a failure, we put it in the model and can make improvements faster. Third, which is key, is low-cost rotary steerables. Just five years ago, rotary steerables was a province of only offshore. Now, low-cost rotary steerables for land applications are becoming de rigueur and will become more so.

DC: What are some of the biggest challenges you’re seeing in deepwater and in the Lower Tertiary plays that’s been gaining so much momentum?

Rao: Ultra-deepwater, defined as 5,000 ft or greater, is of critical importance, and almost all the lower tertiary plays are ultra-deep. Before lower tertiary, almost all deepwater production came from young rock. That means 5 million to 20 million year old rock versus 30 to 60 million years old rock in the Lower Tertiary. So what is the significance of that? By chance, a large part of those rocks are overlain by salt anywhere from a few hundred feet to several thousand feet thick.

First, that salt is very difficult to read through. Second, it’s hell to drill through. It’s actually alive — if you drill a hole in it, the salt will move and close in on you. That means casing must be much stronger.

Below the salt, there are other problems. Turns out that the salt rubbleized the rock below as it moved out over the formation. This means the rock below the salt sheet is not compacted — it’s rubble. That makes drilling much more difficult and therefore costlier.

There are also HPHT issues because almost of all this will be high pressure, and some of it high temperature. High pressure will require more sophisticated steels and thicker walls. With thicker walls in LWD, that means more compact electronics, or lower-profile electronics, have to be used.

Finally, you’ll need very reliable rotary steerables for this because there is no margin for error in expensive wells. Nonproductive time becomes a key. Real time is not optional anymore because you need real-time drilling controls to reduce nonproductive time. These are all challenges we’re meeting in deepwater and the Lower Tertiary.

DC: How close are we to realizing mono-diameter wells? What are the obstacles that remain in that path?

Rao: The industry will have a mono-diameter well in 2008, but what does that mean? It means many stands of casing of the same size hooked together. It doesn’t mean the same size top to bottom. My personal view is that the purpose of mono-diameter is to get the same hole size beyond a certain point, not necessarily to the top. I believe you should come out of mono-diameter the size you want, whether it’s 4 ½ or 9 5/8, then go to bottom with it. Mono-diameter allows the production conduit to be bigger, that is the important thing.
Aside from the Lower Tertiary discussion, rock in deepwater is generally younger. They’re less compacted; therefore there are more overpressure zones that cause you to lose hole size. With mono-diameter, the same hole size can be kept no matter how often the well runs into an overpressure zone. This makes well planning much simpler.

DC: So what is the big hurdle to mono-diameter?

Rao: Mental. A drilling engineer must get used to thinking it will be one size all the way. Then they have to stock only one size of casing and depend on it. They can’t decide afterwards they can’t do it anymore. Once they build up the confidence to take that risk, it will be fantastic. Imagine the simplicity on the rig with having one size.

Materials will eventually become an issue due to collapse strength, but that’s improving. Once the materials issue is solved, you can drill to unlimited depths. In my view, everything in the industry is ready for it.

DC: What cost increases have you seen and what are the major factors driving the increase?

Rao: Overall costs have gone up, both from a rig standpoint and a service standpoint. Service costs have gone up because our costs have gone up. A big area is the increase in alloy steel pricing, which is directly due to the price increase of nickel. Another big area is access to specialized machining. That has become difficult so we have do engineering developments to ameliorate that, and lead times are up dramatically.

DC: Are onshore facilities and real-time management technologies being used to its full extent to operate offshore operations? What are the remaining challenges? Bed space on many offshore rigs are still a challenge – why isn’t onshore management centers helping?

Rao: No, it’s not being used to its fullest extent, but we’re improving dramatically as we go. The bedspace problem will get better eventually. Real time improves the effectiveness of the operation, but initially it won’t necessarily reduce the number of personnel on the rig. When computers first came out, people promised it would reduce manning. Of course that didn’t happen. People just learned to use it more effectively to produce more output. Like real-time management today, we’re getting more output. Eventually, though, I absolutely believe that bedspace will drop.

Real time is also changing the way we train people. We no longer have to give them loads of information to make them effective because information is at their fingertips. Instead, we train them to access information. Real-time operations will also make the workforce more inclusive for people who can’t go offshore for some reason. Retirees can be part-timers, and there may be more women in the workforce. That’s a part we haven’t fully realized yet.

DC: Have there been changes in the way operators and service companies work towards developing and implementing frontier technologies?

Rao: Yes, the degree of cooperation has gone up significantly. IOCs and in particular NOCs are asking for more co-development than ever before. In January 2008 there will be an announcement of a consortium between several oil companies and three service companies to address a very aggressive area of pre-competitive research. It will singularly target that critical imperative of increasing net recoveries. I think you will see an unprecedented type of collaboration in the industry.